gary a. dodge, #0897 hatch, james & dodge 10 west...

Gary A. Dodge, #0897 Hatch, James & Dodge 10 West Broadway, Suite 400 Salt Lake City, UT 84101 Telephone: 801-363-6363 Facsimile: 801-363-6666 Email: [email protected] Attorneys for UAE Intervention Group

________________________________________________________________________

BEFORE THE PUBLIC SERVICE COMMISSION OF UTAH

In the Matter of the Application of Rocky Mountain Power for Authority to Increase its Retail Electric Utility Service Rates in Utah and for Approval of its Proposed Electric Service Schedules and Electric Service Regulations

Docket No. 11-035-200

PREFILED DIRECT TESTIMONY OF NEAL TOWNSEND

[COST OF SERVICE / RATE SPREAD / RATE DESIGN]

The UAE Intervention Group (UAE) hereby submits the Prefiled Direct Testimony of

Neal Townsend on cost of service, rate spread and rate design issues.

DATED this 22nd day of June, 2012.

/s/ ____________________________

Gary A. Dodge, Attorney for UAE

ii

CERTIFICATE OF SERVICE

I hereby certify that a true and correct copy of the foregoing was served by email this 22nd day of June, 2012, on the following:

Mark C. Moench Yvonne R. Hogle Daniel E. Solander Rocky Mountain Power 201 South Main Street, Suite 2300 Salt Lake City, Utah 84111 [email protected] [email protected] [email protected] Patricia Schmid Wesley D. Felix Assistant Attorneys General 500 Heber M. Wells Building 160 East 300 South Salt Lake City, UT 84111 [email protected] [email protected] Paul Proctor Assistant Attorney General 160 East 300 South, 5th Floor Salt Lake City, UT 84111 [email protected] F. Robert Reeder William J. Evans Vicki M. Baldwin Parsons Behle & Latimer One Utah Center, Suite 1800 201 S Main St. Salt Lake City, UT 84111 [email protected] [email protected] [email protected]

Holly Rachel Smith, Esq. Hitt Business Center 3803 Rectortown Road Marshall, VA 20115 [email protected] Ryan L. Kelly Kelly & Bramwell, P.C. 11576 South State Street Bldg. 1002 Draper, UT 84020 [email protected] Steve W. Chriss Wal-Mart Stores, Inc. 2001 SE 10th Street Bentonville, AR 72716-0550 [email protected] Kurt J. Boehm, Esq. Jody M. Kyler, Esq. BOEHM, KURTZ & LOWRY 36 East Seventh Street, Suite 1510 Cincinnati, Ohio 45202 [email protected] [email protected] Brian W. Burnett, Esq. CALLISTER NEBEKER & MCCULLOUGH Zions Bank Building 10 East South Temple, Suite 900 Salt Lake City, Utah 84133 [email protected] Stephen J. Baron J. Kennedy & Associates 570 Colonial Park Drive, Suite 305 Roswell, GA 30075 [email protected]

iii

Peter J. Mattheis Eric J. Lacey BRICKFIELD, BURCHETTE, RITTS & STONE, P.C. 1025 Thomas Jefferson Street, N.W. 800 West Tower Washington, D.C. 20007 [email protected] [email protected] Gerald H. Kinghorn Jeremy R. Cook PARSONS KINGHORN HARRlS 111 East Broadway, 11 the Floor Salt Lake City, UT 84111 [email protected] [email protected] Roger Swenson US Magnesium LLC 238 North 2200 West Salt Lake City, UT 84114-6751 [email protected] Sophie Hayes Sarah Wright Utah Clean Energy 1014 2nd Avenue Salt Lake City, UT 84111 [email protected] [email protected] Rob Dubuc Western Resource Advocates 150 South 600 East, Suite 2A Salt Lake City, UT 84102 [email protected] Steven S. Michel Western Resource Advocates 409 E. Palace Ave. Unit 2 Santa Fe, NM 87501 [email protected]

Nancy Kelly Western Resource Advocates 9463 N. Swallow Rd. Pocatello, ID 83201 [email protected] Betsy Wolf Salt Lake Community Action Program 764 South 200 West Salt Lake City, Utah 84101 [email protected] Charles Johnson 1086 – 7B Pleasant Blvd. Toronto, Ontario M4T1K2 [email protected] Gloria D. Smith Sierra Club 85 Second Street, Second floor San Francisco, CA 94105 [email protected] Travis Ritchie Sierra Club 85 Second Street, Second floor San Francisco, CA 94105 [email protected] Capt Samuel T. Miller USAF Utility Law Field Support Center 139 Barnes Ave, Suite 1 Tyndall AFB, FL 32403 [email protected] Lt Col Lance Thaxton Civil Law Attorney OO-ALC/JA 6026 Cedar Lane , Bldg 1278 Hill AFB, Utah 84056 Arthur Sandack 8 East Broadway, Ste 411 Salt Lake City, Utah 84111 [email protected]

iv

Bruce Plenk 2958 N St Augustine Pl Tucson, AZ 85712 [email protected]

Janee Briesemeister AARP 98 San Jacinto Blvd. Ste. 750 Austin, TX 78701 [email protected] Randy N. Parker, CEO Utah Farm Bureau Federation 9865 South State Street Sandy, Utah 84070 [email protected]

Leland Hogan, President Utah Farm Bureau Federation 9865 South State Street Sandy, Utah 84070 [email protected]

/s/________________________________

UAE Exhibit COS 2.0 Direct Testimony of Neal Townsend

UPSC Docket 11-035-200

BEFORE

THE PUBLIC SERVICE COMMISSION OF UTAH

Direct Testimony of Neal Townsend

on behalf of

UAE

Docket No. 11-035-200

[Cost of Service / Rate Spread / Rate Design]

June 22, 2012


UPSC Docket 11-035-200 Page 1 of 17

DIRECT TESTIMONY OF NEAL TOWNSEND 1

2

INTRODUCTION 3

Q. Please state your name and business address. 4

A. My name is Neal Townsend. My business address is 215 South State 5

Street, Suite 200, Salt Lake City, Utah, 84111. 6

Q. By whom are you employed and in what capacity? 7

A. I am a Director for Energy Strategies, LLC. Energy Strategies is a private 8

consulting firm specializing in economic and policy analysis applicable to energy 9

production, transportation, and consumption. 10

Q. On whose behalf are you testifying in this proceeding? 11

A. My testimony is being sponsored by the Utah Association of Energy Users 12

Intervention Group (“UAE”). 13

Q. Please describe your professional experience and qualifications. 14

A. I have provided regulatory and technical support on a variety of energy 15

projects at Energy Strategies since I joined the firm in 2001. Prior to my 16

employment at Energy Strategies, I was employed by the Utah Division of Public 17

Utilities as a Rate Analyst from 1998 to 2001. I have also worked in the 18

aerospace, oil and natural gas industries. 19

Q. Have you previously testified before this Commission? 20

A. Yes. Since 1997, I have testified in eight dockets before the Utah Public 21

Service Commission on electricity and natural gas matters. 22



Q. Have you testified previously before any other state utility regulatory 23

commissions? 24

A. Yes. I have testified in utility regulatory proceedings before the Arkansas 25

Public Service Commission, the Illinois Commerce Commission, the Indiana 26

Utility Regulatory Commission, the Kentucky Public Service Commission, the 27

Michigan Public Service Commission, the Public Utility Commission of Oregon, 28

the Public Utility Commission of Texas, the Utah Public Service Commission, the 29

Virginia Corporation Commission, and the Public Service Commission of West 30

Virginia. A more detailed description of my qualifications is contained in 31

Attachment A, attached to this testimony. 32

33

OVERVIEW AND CONCLUSIONS 34

Q. What is the purpose of your testimony in this proceeding? 35

A. My testimony addresses the following cost-of-service, spread, and rate 36

design issues: 37

(1) RMP's cost-of-service study. 38

(2) The appropriate spread of the revenue requirement increase that will 39

be determined in this case. 40

(3) RMP's proposed Schedule 8 and 9 rate design. 41

(4) Schedule 8 Tariff language. 42

Q. Please summarize your conclusions and recommendations. 43



A. (1) The seasonality of Utah loads is not adequately addressed or reflected 44

in RMP’s cost of service study. Among other things, monthly peak load 45

weightings should be retained to partially address this seasonality. 46

(2) RMP’s cost-of-service study inappropriately assigns a significant 47

portion of the revenue credits associated with Schedule 21, Schedule 31, and 48

Special Contract 3 to the distribution, retail, and miscellaneous functions. At a 49

minimum, I recommend that the revenues associated with Special Contract 3 be 50

applied as a credit against only production and transmission costs. 51

(3) I present a modified rate spread proposal which takes account of my 52

recommended changes to RMP’s cost-of-serve study. My rate spread retains the 53

basic structure of RMP witness William R. Griffith’s proposal and is reasonable 54

in that it recognizes the direction of change indicated by the cost-of-service study, 55

while, like Mr. Griffith’s proposal, not adhering rigidly to class revenue 56

deficiencies indicated by any given cost-of-service study. 57

(4) The Commission should not adhere strictly to class revenue 58

deficiencies indicated by any given cost-of-service study for a number of reasons, 59

including the fact that cost of service analysis is more art than science, that the 60

cost of service methodologies typically used in Utah do not adequately recognize 61

the cost-causative nature of Utah’s seasonal loads, and the fact that other 62

ratemaking principles, including the principle of gradualism, should be employed 63

to mitigate the severe impacts of the recent major recession on Utah businesses. 64



(5) I recommend the Commission adopt the approach recommended by 65

Mr. Griffith for the design of Schedule 8 and 9 rates. 66

(6) I recommend that the Commission modify the Schedule 8 tariff 67

language to provide that a customer will be moved onto Schedule 8 only if its 68

peak load is at or exceeds 1,000 kW in at least half of the months in a rolling 12-69

month period, and that a Schedule 8 customer be allowed to move back to 70

Schedule 6 if its peak load falls below 1,000 kW more than half of the months in a 71

subsequent 12-month period. 72

73

COST OF SERVICE 74

Q. Have you reviewed the class cost-of-service (COS) study presented by RMP 75

witness C. Craig Paice? 76

A. Yes, the results of Mr. Paice's study are shown in RMP Exhibit ___ (CCP-77

1). 78

Q. Do you have any comments on the Company's COS study? 79

A. Yes. I disagree with Mr. Paice's elimination of the weightings previously 80

applied to the monthly class peak loads used to allocate generation and 81

transmission fixed costs. These weightings were introduced in the 2006 general 82

rate case in an effort to begin to address the significant seasonal nature of Utah’s 83

peak loads, particularly its summer peaks. While I recognize some may argue 84

that the use of these weights perpetuates a minor inconsistency between the 85

derivation of the factors used in the inter-jurisdictional cost allocation model and 86



the class COS model, I nevertheless believe the weighting is appropriate in light 87

of Utah's increasing summer peaks. 88

Q. How are these monthly peak weightings derived? 89

A. The monthly peak weights that have been used since 2006 are derived by 90

comparing each of the monthly system peak loads during the test period to the 91

maximum system peak load for the test period. For example, the monthly system 92

peak load in the first month of the test period, June 2012, is forecasted to be 8,444 93

MW; the maximum system peak load during the test period is 9,235 MW which is 94

forecasted in July 2012. Thus, the June 2012 weighting is 91.44% (8,444 MW ÷ 95

9.235 MW). During the test period the monthly weightings ranged from 81.83% 96

to 100%. 97

Q. Do these weights dramatically alter the COS results? 98

A. No. I present the results of the COS using the weighted monthly peaks in 99

UAE Exhibit COS 2.1 (TNT-1). In Table TNT-1, below, I compare the class 100

increases required to achieve the requested rate of return using the monthly peak 101

weighted results to the class increase required to achieve the requested rate of 102

return under RMP's COS results.1 As these results show, the use of these weights 103

has only a very modest impact on the COS results. I believe the monthly 104

weightings should be retained because they begin to address the significant 105

impacts of seasonal peak loads in Utah. 106

1 See RMP witness C. Craig Paice Exhibit ___ (CCP-1).



Table TNT-1 107

Comparison of RMP COS Revenue Change 108 and Revenue Change with Weighted Monthly Peak Loads 109

110

Increase IncreaseSchedule (Decrease) Percent (Decrease) Percent

No. Description to = ROR Change to = ROR Change1 Residential $79,988,260 12.31% $81,469,045 12.53%6 General Service - Large $29,411,385 6.19% $28,986,258 6.10%8 General Service - Over 1 MW $12,036,471 8.50% $11,832,608 8.36%

7,11,12 Street & Area Lighting ($346,450) -2.86% ($350,452) -2.89%9 General Service - High Voltage $32,529,400 14.19% $31,943,488 13.93%

10 Irrigation $2,172,274 16.49% $2,244,673 17.04%15 Traffic Signals $47,246 8.08% $46,630 7.97%15 Outdoor Lighting ($150,539) -13.15% ($151,268) -13.22%23 General Service - Small $6,509,155 5.01% $6,561,870 5.05%

SpC Customer 1 $5,232,863 21.60% $5,151,093 21.26%SpC Customer 2 $4,837,276 17.95% $4,533,392 16.82%

Total Utah Jurisdiction $172,267,339 10.11% $172,267,339 10.11%

COS Results using MonthlySystem Peak Weights

RMP COS Results (CCP-1)

111

Q. Are there other ways in which the seasonality of Utah's loads could be 112

addressed in a COS study? 113

A. Yes. There are many alternatives that could better reflect the cost-114

causative nature of Utah’s seasonal peak loads. For example, the monthly peak 115

weightings could be derived using Utah monthly peak loads instead of the system 116

peak loads. Alternatively, other cost-of-service approaches could be used to 117

allocate the fixed generation and transmission costs in a manner that better 118

reflects cost causation. 119

Q. What is your recommendation to the Commission on this issue? 120

A. At a minimum, I believe the monthly peak load weightings that have been 121

used in Utah since 2006 should be retained. 122

Q. Do you have any other observations related to RMP's COS study? 123



A. Yes. RMP’s COS study includes $64 million dollars that are treated as 124

revenue credits to offset the costs of providing electric service to customers. The 125

revenues are related to Schedule 21 (Electric Furnace Service), Schedule 31 126

(Partial Requirements Service), and Special Contract 3. The vast majority of this 127

$64 million is for electric service provided to Special Contract 3. 128

Q. How has RMP treated these revenue credits in its COS study? 129

A. RMP has imputed a portion of these revenue across all five functions 130

(production, transmission, distribution, retail, and miscellaneous) in its COS 131

study. For example, approximately $10 million of the $64 million is credited 132

against the distribution function costs. 133

Q. Do you agree with RMP's proposed revenue credit treatment? 134

A. No. As I noted above, the vast majority of these revenues are related to 135

Special Contract 3. In my opinion, these revenues should only be applied against 136

the production and transmission functions. Like Schedule 9 industrial customers, 137

Special Contract 3 takes service at transmission voltage. Distribution facilities are 138

not used to serve this customer. Therefore, it is not appropriate to credit any of 139

this revenue against distribution-related costs. For the same reason, it may also be 140

appropriate to credit most of the other revenue credits (Schedules 21 and 31) to 141

the production and transmission functions. 142

Q. Have you assessed the impact of assigning these revenue credits solely to the 143

production and transmission functions? 144



A. Yes. As a sensitivity analysis, I credited the entire $64 million to the 145

production and transmission functions. I present the results of the COS with these 146

revenues assigned solely to the production and transmission functions in UAE 147

Exhibit COS 2.2 (TNT-2). In Table TNT-2, I compare the class increases 148

required to achieve the requested rate of return with these revenues credited 149

against production and transmission costs to the class increase required to achieve 150

the requested rate of return under RMP's COS results. As these results show, the 151

treatment of these revenue credits also has a relatively modest impact on the COS 152

results. 153

Table TNT-2 154

Comparison of RMP COS Revenue Change and Revenue Change with 155 Revenue Credits Assigned to Production and Transmission Functions 156

157







RMP COS Results (CCP-1) COS Results with RevenueCredit Assigned to P&T

158

Q. What is your recommendation to the Commission on the proper treatment of 159

the revenue credits in the COS study? 160



A. At a minimum, I recommend that the revenues associated with Special 161

Contract 3 be applied as a credit against production and transmission costs. 162

Q. Have you performed a sensitivity analysis that combines the impact of using 163

the monthly system peak weights with the change in the treatment of these 164

revenue credits? 165

A. Yes. I present the combined effect of these changes on the COS results in 166

UAE Exhibit COS 2.3 (TNT-3). In Table TNT-3, I compare the class increases 167

required to achieve the requested rate of return with the combined impact of these 168

changes to RMP's COS results. As these results show, in combination these 169

changes have only a modest impact on the COS results. 170

Table TNT-3 171

Comparison of RMP COS Revenue Change and Revenue Change with 172 Combined Effect of Weighted Monthly Peak Loads and the Revenue Credits 173

Assigned to Production and Transmission Functions 174 175







RMP COS Results (CCP-1) COS Results using Mo. PkWgts & Rev. Cr. to P&T

176



Q. Do you have any other recommendations related to the COS study at this 177

time? 178

A. No, although I believe that additional steps could be appropriate to better 179

reflect cost causation, particularly as it relates to Utah’s summer peaks. 180

181

RATE SPREAD 182

Q. What revenue increase is RMP recommending for the Utah jurisdiction? 183

A. PacifiCorp has requested a $172,267,339, or 9.7% overall, Utah revenue 184

increase. 185

Q. Have you reviewed the rate spread proposal presented by RMP witness 186

William R. Griffith? 187

A. Yes, I have. As shown on RMP Exhibit ___ (WRG-1), if Special Contract 188

1, Special Contract 2, and Annual Guarantee Adjustment (AGA) revenues are 189

excluded, this $172,267,339 represents a 10% overall Utah revenue increase. Mr. 190

Griffith is proposing a rate spread in which customers served on Schedules 6 and 191

23 would receive an 8.54 percent increase, approximately equal to 1.5 percent 192

below the system average increase excluding the revenue for the two special 193

contracts and the AGA (which I will refer to as the “Modified System Average” 194

hereafter). Customers served on Schedule 8 and Schedule 15T would receive a 195

9.54 percent increase, approximately equal to 0.5 percent below the Modified 196

System Average. Residential customers on Schedules 1, 2, and 3 would receive a 197

10.54 percent increase, approximately equal to 0.5 percent above the Modified 198



System Average increase. Customers served on Schedule 9, Schedule 21, and 199

Schedule 31, plus the Special Contract 3 customer would receive a 12.54 percent 200

increase, approximately equal to 2.5 percent above the Modified System Average 201

increase. Irrigation customers served on Schedule 10 would receive a 13.54 202

percent increase, approximately equal to 3.5 percent above the Modified System 203

Average increase. Finally, the remaining lighting customers would receive a 0 204

percent increase. 205

Q. What is your assessment of Mr. Griffith’s proposal? 206

A. Given the COS results that RMP has presented in this case, Mr. Griffith's 207

spread is not unreasonable. However, based on the COS modifications I 208

performed, I recommend several adjustments to Mr. Griffith's spread proposal. 209

With these adjustments, I believe my proposed spread is more reasonable at 210

RMP’s requested revenue requirement. The proposal recognizes the direction of 211

change indicated by my adjustments discussed above to RMP’s cost-of-service 212

study. Under this recommended spread, classes earning returns below the system 213

average receive percentage rate increases that are above the average, and vice 214

versa, while classes earning close to the average retail return receive an increase 215

approximately equal to the system average increase. At the same time, this spread 216

proposal does not rigidly adhere to the class revenue deficiencies indicated by 217

RMP’s cost-of-service study. I believe this is a reasonable approach. 218

Q. Can you describe the adjustments that you recommend? 219



A. In its revenue requirement testimony, UAE recommended an adjustment 220

to recognize the incremental revenue that will be recovered from Special Contract 221

customers 1 and 2. I believe these additional revenues should be considered in 222

determining rate spread.2 223

Based on the results of the COS sensitivity studies discussed above, I 224

recommend that the residential schedules (Schs. 1, 2, & 3) and Schedule 9 should 225

receive the same percentage increase because the cost of service results for these 226

two major classes are reasonably similar. This recommendation will result in a 227

change in the rate-spread midpoint from 10.54% to 10.81%. However, for the 228

remaining rate schedules, I recommend maintaining the relationship Mr. Griffith 229

proposed for each schedule relative to the rate spread midpoint. I note that since I 230

am recommending a different percentage change for Schedule 9 that the 231

incremental revenues from the special contracts tied to the Schedule 9 will change 232

as well. I have attempted to estimate this impact and have incorporated its effects 233

into my recommended rate spread. 234

I present UAE’s recommended rate spread at RMP’s requested revenue 235

requirement in UAE Exhibit COS 2.4 (TNT-4), which reflects these proposed 236

changes. 237

Q. Is it reasonable to not adhere strictly to the class revenue deficiencies 238

indicated by RMP’s cost-of-service study? 239

2 The amount of incremental revenues that will be recovered from the Special Contracts is governed by the terms of each contract. The amount of incremental revenue for each contract is dependent on the outcome of this general rate case.



A. Yes. Any approach to cost-of-service analysis is as much art as science, 240

and will provide only general guidance for rate spread determinations. Moreover, 241

as a general matter, cost-of-service studies should yield under proper 242

circumstances to other ratemaking principles, such as the principle of gradualism, 243

which takes into consideration the impact of rate increases on various customer 244

groups. In this proceeding, the principle of gradualism is particularly important 245

for customers taking service under Schedule 9, in light of the failure of RMP’s 246

COS methodology to account for the significant impacts of Utah’s summer peaks 247

as well as the economically tenuous circumstances faced by American industry as 248

businesses try to recover from the recent recession. RMP's requested annual rate 249

case increases, which are projected to continue for the foreseeable future, have 250

generally been in the double digit percentage range for Utah's industrial customers 251

for several years, and are difficult for Utah businesses to absorb. 252

Q. What is your recommendation if the actual revenue increase granted by the 253

Commission is lower than that requested by RMP? 254

A. If the revenue requirement approved by the Commission is less than that 255

requested by RMP, I recommend that the rate spread proposed in UAE Exhibit 256

COS 2.4 (TNT-4) be used as the starting point for spreading the approved revenue 257

change. Specifically, the revenue apportionment produced by my suggested rate 258

spread should be used as the basis for spreading any smaller revenue change. 259

Q. Please explain your recommendation further. 260



A. When I refer to the “revenue apportionment” produced by the initial 261

proposed rate spread I am referring to each class’s percentage share of total 262

revenue requirement that results from that spread. For example, as shown in UAE 263

Exhibit COS 2.5 (TNT-5), column (f), Residential customers would pay 38% of 264

the total revenue requirement, excluding Special Contracts 1 and 2, AGA, and 265

Street lighting revenues. If the Commission were to determine that this proposed 266

rate spread is reasonable, then by extension, the corresponding revenue 267

apportionment is reasonable as well and it should be used to spread the ultimate 268

revenue requirement increase. 269

My recommendation is to apply the percentage revenue apportionment 270

that results from my initial recommended rate spread to the final revenue 271

requirement approved by the Commission. The advantage of this approach is that 272

it balances the application of gradualism with movement toward cost-of-service. 273

If there is agreement (or a determination) that a given revenue apportionment 274

reasonably accomplishes this balance, then this balance should be retained for a 275

range of different revenue requirements. My recommendation accomplishes this 276

objective. 277

Q. Do you have an example of how this approach would work? 278

A. Yes. An example is presented in UAE Exhibit COS 2.5 (TNT-5) using a 279

hypothetical revenue increase of $86.1 million. 280

281

282



SCHEDULE 8 AND 9 RATE DESIGN 283

Q. Have you reviewed RMP's proposed rate design for Schedules 8 and 9? 284

A. Yes, the proposed rate designs are presented in RMP Exhibit ___ (WRG-285

3). According to the testimony of RMP witness William R. Griffith, the 286

Company proposes to uniformly increase the facility, demand and energy charges 287

to reflect the proposed revenue requirement change. In addition, the Company 288

proposes to increase the monthly customer charge associated with each schedule.3 289

Q. What is your recommendation to the Commission on the Company's 290

approach to designing the rates for Schedule 8 and 9? 291

A. I agree with the approach recommended by Mr. Griffith for the design of 292

Schedule 8 and 9 rates and I recommend that the Commission adopt it. 293

294

SCHEDULE 8 TARIFF LANGUAGE 295

Q. What tariff schedules are used to serve distribution voltage general service 296

commercial customers? 297

A. General service distribution voltage commercial customers (i.e. those 298

served at a voltage level less than 46 kilovolts [kV]) are served on either Schedule 299

6 or Schedule 8. 300

Q. What determines whether a customer is served on Schedule 6 or 8? 301

A. Distribution voltage general service customers are generally served on 302

Schedule 6 as long as their peak demand is below 1,000 kilowatts (kW). A 303

3 See RMP witness William R. Griffith direct testimony, p. 12.



customer whose monthly peak demand reaches 1,000 kW or greater twice in any 304

consecutive 18-month period is automatically moved to Schedule 8. Under the 305

Schedule 8 tariff, a customer must remain on Schedule 8 for at least 36 months (or 306

18 months if the customer has never before been moved to Schedule 8) even if its 307

usage never again reaches the 1,000 kW level. Once the 36-month period (or 18-308

months if applicable) passes without the customer exceeding 1,000 kW even 309

once, the customer may ask to move back to Schedule 6; the move is not 310

automatic. 311

Q. Do you believe that these requirements for moving onto and off of Schedule 8 312

are justified or reasonable? 313

A. No. Schedule 8 was adopted by stipulation to create a separate schedule 314

for “larger” commercial customers that were not transmission level (Schedule 9) 315

customers. The 1,000 kW threshold, the number of monthly peak “incursions” 316

above or below that level to trigger a move to Schedule 8 or the right to move 317

back to Schedule 6, and the 36-month (or 18) measurement period, are all 318

arbitrary, negotiated numbers or levels that lack any strong basis or justification. 319

Having observed the impacts of Schedule 8 now for several years, I do not believe 320

that they remain reasonable. 321

Q. Please explain. 322

A. There is no sound or compelling reason to force commercial customers 323

onto or off of Schedule 6 or Schedule 8 based solely on infrequent load variations 324

above or below the arbitrary 1,000 kW level. That breaking point was selected to 325



distinguish between “smaller” and “larger” Schedule 6 customers. Rigid 326

application of this breaking point to force customers to remain on one schedule or 327

the other serves no reasonable or valid purpose. Rather, a customer should be and 328

remain on Schedule 8 only if it is in fact consistently a “larger” customer with 329

peak loads generally in excess of 1,000 kW or on Schedule 6 if it is consistently a 330

“smaller” customer with peak loads generally below 1,000 kW. 331

Q. What is your recommendation? 332

A. I recommend that the Commission modify the Schedule 8 tariff language 333

to provide that a customer will be moved onto Schedule 8 only if its monthly peak 334

load is at or exceeds 1,000 kW in at least half of the months in a rolling 12-month 335

period. Once on Schedule 8, I recommend that a customer be allowed to move 336

back to Schedule 6 if its monthly peak load is below 1,000 kW in more than half 337

of the months during a subsequent 12-month rolling period. I believe this is a 338

more reasonable basis for distinguishing between smaller general service 339

commercial customers who should be on Schedule 6 and larger general service 340

commercial customers who should be on a separate schedule. 341

Q. Does this conclude your direct testimony? 342

A. Yes, it does. 343

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